Exploring a subsurface region that contains a target sector of interest

ABSTRACT

A system and method are disclosed for exploring a subsurface region that contains a target sector of interest. The method comprises providing information about the harmonic response for the target sector of interest and a seismic source. The method comprises controlling the seismic source to provide seismic waves in a narrowband selected on the basis of the information about the harmonic response for the target sector of interest. The method comprises activating the seismic source so as to introduce seismic waves into the subsurface sector and sensing reflections of the seismic waves at a seismic receiver.

CROSS-REFERENCE TO RELATED PATENT APPLICATIONS

This application is a continuation-in-part of application Ser. No.12/502,169, filed Jul. 13, 2009, which is a continuation of applicationSer. No. 11/451,571, filed Jun. 13, 2006, issued as U.S. Pat. No.7,382,684 on Jun. 3, 2008, the disclosures of both of which are hereinincorporated by reference in their entireties.

BACKGROUND

1. Field of the Invention

The invention relates generally to the field of seismic dataacquisition. More specifically, the invention relates to methods forselective bandlimited data acquisition resulting in improved imaging ofeconomically valuable or useful earth targets of interest.

2. Background Technology

Surface acoustic sources generate seismic waves from the surface andoperate at relatively low frequencies resulting in low-resolutionsurveys. A few downhole seismic sources have been developed whichtransmit acoustic waves into the formation through a borehole medium.These downhole sources can operate at a higher frequency than surfacesources but often do not generate enough energy to result in accuratesurveys.

Conventional downhole sources include:

the cylindrical bender source using piezoelectric rings bonded to a tubedeveloped by Southeast Research Institute and described in Balogh etal.'s, “New Piezoelectric Transducer for Hole-to-Hole SeismicApplications,” 58th Annual International Meeting of the Society ofExploration Geophysics (1988), Session DEV2.5; the electro-acoustictransducer cylindrical bender source developed by Kompanek and describedin U.S. Pat. No. 4,651,044; the arc discharge pulse source developed bySouthwestern Research Institute as described in U.S. Pat. No. 5,228,011;the swept frequency borehole source developed by Western Atlas anddescribed in Owen et al.'s, “Arc Discharge Pulse Source for BoreholeSeismic Applications,” 58th Annual International Meeting of the Societyof Exploration Geophysics (1988), Session DEV2.4; the potential energy“drop mass” source developed by Institut Francais du Petrole (IFP) asdescribed in U.S. Pat. No. 4,505,362; the hammer launched sourcedeveloped by OYO Corporation and described in Kennedy et al.'s “ASwept-Frequency Borehole Source for Inverse VSP and Cross-BoreholeSurveying,” 7.sup.th Geophysical Conference of the Australian Society ofExploration Geophysics (1989), Volume 20, pages 133-136; and the orbitalvibrator developed by Conoco and described in Ziolkowksi et al.'s“Determination of Tube-Wave to Body-Wave Ratio for Conoco BoreholeOrbital Source,” 69th Annual International Meeting of the Society ofExploration Geophysics (1999), pages 156-159.

A few sources have been developed that are clamped against the boreholewall. One source utilizes a hydraulic vibrator clamped against theborehole wall to oscillate a reaction mass axially or radially and ismore fully described in Turpening et al.'s “Imaging with ReverseVertical Seismic Profiles Using a Downhole, Hydraulic, Axial Vibrator,”62nd Meeting of EAGE (2000), Session P0161.

Some of the most recent and promising techniques for improved imaginguse complicated mathematics, such as Fourier transforms, to deconstructthe seismic data into discrete frequencies. As is well known, a Fouriertransform utilizes windows.

When the harmonic frequency of the desired target of interest isdisplayed, the image becomes much clearer than the broadband seismicimage. This resonance effect is described in The Leading Edge,Interpretational Applications of Spectral Decomposition in ReservoirCharacterization, Greg Partyka, 1999.

Recently, the more advanced technique of using wavelet transforms, whichmitigate the windowing problems associated with Fourier transforms, hasbeen successfully applied to geophysical problems.

Patent application 20050010366 of John Castagna describes the techniqueof Instantaneous Spectral Analysis, which decomposes the seismic signalfrom the time domain to the frequency domain by superimposing members ofa preselected “wavelet dictionary” onto the trace, cross-correlating,and subtracting the energy of the wavelets until some predefined minimumthreshold is reached. The result is a spectrum for each time location onthe trace. More on this subject can be found in “The Leading Edge:Instantaneous Spectral Analysis”, John Castagna, 2003. Partyka, G. A.,Gridley, J. A., and Lopez, J. A., 1999, Interpretational aspects ofspectral decomposition in reservoir characterization: The Leading Edge,18, 353-360. Castagna, J. P., Sun, Shenjie, and Siegfried, R. W., 2003,Instantaneous spectral analysis: Detection of low-frequency shadowsassociated with hydrocarbons, 120-127. Marfurt, K. J. and Kirlin, R. L.,2001, Narrow-band spectral analysis and thin-bed tuning: Geophysics, 66,1274-1283. The results obtained from data deconstruction are essentiallybased on mathematical estimates.

Another recent industry development is time-lapse production imagingcommonly termed 4D seismic monitoring. It is a method of viewing thereservoir with repeat surveys to determine how it is drainingdynamically. Essentially, the seismic surveys are repeated with as muchprecision as possible in order to generate data sets that differ onlywith respect to changes associated with reservoir production. By findingthe residual between the time-lapse images, one is able to infersubsurface fluid flow patterns and place constraints on fluid conduitsand baffles associated with the drainage, thereby enabling one to modifyreservoir models and future drilling plans. Because these changes can besubtle, any improvement of the signal-to-noise ratio would have abeneficial effect for 4D monitoring.

Accurate repositioning of the seismic source is useful in achieving 4Dmonitoring precision. Furthermore, a priori knowledge of the sourcesignature would be beneficial. More on the subject can be found in thebook “4D Reservoir Monitoring and Characterization” by Dr. RodneyCalvert.

The frequency range that is providing a given image is governed by theseismic wavelet, which initially represents the source signature andthen changes as it experiences a number of earth-filtering effects,including absorption, geometrical spreading, and scattering. Betterknowledge of the seismic source improves processes that remove the earthfiltering effects.

Additional Related prior art can be found in the following:

6,985,815 January 2006 Castagna et al, 6,661,737 December 2003Wisniewski et al, 5,093,811 March 1992 Mellor et al, 6,619,394 September2003 Soliman et al, 200,200,700,17 June 2002 Soliman et al, 5,077,697December 1991 Chang, 5,418,335 May 1995 Winbow, 5,371,330 December 1994Winbow, 200,500,757,90 April 2005 Taner, M. Turhan et al, 6,814,141November 2004 Huh et al, 200,201,486,06 October 2002 Zheng, Shunfeng etal, 200,201,793,64 December 2002 Bussear, Terry R et al,

Variable frequency seismic sources

U.S. Pat. Nos. 4,014,403, 4,049,077, 4,410,062, 4,483,411 and 4,578,784issued to Joseph F. Mifsud describe tunable frequency land and marineseismic vibrators.

U.S. Pat. No. 4,014,403 relates to a vibrator in which the frequency ofvibration changes as the stiffness of a spring is automaticallyadjusted. As a result, the impedance of the spring resonates with theimpedance of the reaction mass to maximize the reaction impedance,thereby increasing the operating efficiency of the vibrator.

U.S. Pat. No. 4,049,077 shows the use of a coupling plate as feedbackfor controlling the vibrator operation. At low frequencies, the feedbackis proportional to the coupling plate position, and at higherfrequencies, the feedback is proportional to the coupling platevelocity.

U.S. Pat. No. 4,410,062 shows a compliant member whose compliance issuch that it is substantially rigid at the natural frequency of thevibrator, and the natural frequency of the driven load of the vibratoris within the seismic spectrum but is higher than the natural frequencyof the vibrator.

U.S. Pat. No. 4,483,411 shows a seismic source, which produces a varyingFM signal at the low end of the acoustic spectrum. The seismic sourceuses stiff oscillating radiators to create a signal in the water. Theseradiators are attached to devices acting as springs with a variablespring rate. Variation of the spring rate as a function of the frequencypermits the device to be tuned for maximum power output.

U.S. Pat. No. 4,578,784 shows a seismic source, which produces a varyingFM signal generally within the 10-100 Hz region of the spectrum.

U.S. Pat. No. 5,146,432 describes a method of characterizingtransducers, and the use of a characterized transducer in themeasurement of the impedance of cement located behind a section of acasing in a borehole.

U.S. Pat. No. 6,928,030 describes a seismic defense system having aclosely monitored seismic source used to relay vital information fromthe source to the receiver.

U.S. Pat. No. 6,661,737 describes a tool including a programmableacoustic source that is controlled by a computer. The tool is used forlogging.

Resonance

U.S. Pat. No. 5,093,811 refers to a fracture study technique in whichresonance is established in the borehole to investigate fracturedimension by comparing the standing wave response at the wellhead to themodeled response.

U.S. Pat. Nos. 5,137,109 and 6,394,221 refer to seismic sources thatsweep through a range of frequencies, the first utilizing hydraulicpressure to vary the resonance frequency of the device itself, and thesecond utilizing a series of variable frequency impacts to sweep theseismic range.

U.S. Pat. No. 5,239,514 refers to a tool having frequencies in the500-1500 Hz range, equivalent to a seismic band of 10-30 Hz, whichincludes much of the typical seismic band. Longer source intervals andstacking are used to increase energy and the signal-to-noise ratio.

U.S. Pat. Nos. 4,671,379 and 4,834,210 describe a tool that creates astanding resonant pressure wave whose frequency depends on the spacingbetween two end means in a borehole. Frictional, structural, andradiated acoustic energy loses are compensated for by continuedapplication of pressure oscillations. This tool relies on establishingresonance at the source.

U.S. Pat. No. 5,081,613 describes a method that generates pressureoscillations that produce resonant frequencies in the wellbore. Afterremoving the effects of known reflectors, the resonant frequencies areused to determine the depth and impedance of downhole obstructions.

As attested by the above references, the geophysical industry hasstruggled, and continues to struggle, to develop improved dataacquisition techniques for improved imaging, as well as for better andeasier characterization of targets of interest that are economicallysuitable for production, and for guidance in selecting optimum welllocations with reduced investments.

SUMMARY

A system and method are disclosed for exploring a subsurface region thatcontains a target sector of interest. The method comprises providinginformation about the harmonic response for the target sector ofinterest and a seismic source. The method comprises controlling theseismic source to provide seismic waves in a narrowband selected on thebasis of the information about the harmonic response for the targetsector of interest. The method comprises activating the seismic sourceso as to introduce seismic waves into the subsurface sector and sensingreflections of the seismic waves at a seismic receiver.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 a illustrates an embodiment in which a bandlimited source and areceiver array are both positioned on the earth surface.

FIG. 1 b illustrates another embodiment in which a bandlimited source ispositioned in a borehole and a receiver array is on the earth surface.

FIGS. 2 a and 2 b illustrate an impingement of bandlimited waves on topand base of a target of interest for a normal-incidence reflection.

FIGS. 3-7 show plots of the response amplitude of a target of interestvs. frequency.

FIG. 3 shows a plot of the fundamental odd frequency as a member of aset of odd harmonics.

FIG. 4 shows a plot of the fundamental even frequency as a member of aset of even harmonics.

FIG. 5 compares the frequency response of two different targets withdifferent thicknesses.

FIG. 6 shows the advantage in terms of response amplitude of anarrowband centered on a resonant frequency over a narrowband centeredon a distortion frequency.

FIG. 7 shows the advantage of using a narrowband centered on a resonantfrequency, which captures the peak broadband amplitude, over using abroadband, which includes distortion frequencies.

FIG. 8 shows a potential target of interest, which could be a thin sandtarget between two shale formations.

FIG. 9 is a schematic block diagram of an apparatus using the exemplarymethods.

FIG. 10 is a flow chart of a method for exploring a subsurface region,according to an exemplary embodiment.

FIGS. 11 a and b are a common-depth-point brute stack of data generatedwith a 4-octave 8-128 Hz wavelet. The shaded event is imaging the EagleFord Shale. FIG. 11 a shows the data with no interpretation by Dr.Hardage. FIG. 11 b shows the data with interpretation by Dr. Hardage.

FIGS. 12 a and b are a common-depth-point brute stack of data generatedwith a half-octave (24-32 Hz) wavelet. The shaded event is an image ofthe Eagle Ford Shale. FIG. 12 a shows the data with no interpretation byDr. Hardage. FIG. 12 b shows the data with interpretation by Dr.Hardage.

FIGS. 13 a and 13 b are a common-depth-point brute stack of datagenerated with a single-octave (16-32 Hz) wavelet. The shaded eventcorresponds to the Eagle Ford Shale. FIG. 13 a shows the data with nointerpretation by Dr. Hardage. FIG. 13 b shows the data withinterpretation by Dr. Hardage.

FIGS. 14 a and 14 b are a common-depth-point brute stack of datagenerated with a half-octave (16-24 Hz) wavelet. The shaded event is theEagle Ford Shale. FIG. 14 a shows the data with no interpretation by Dr.Hardage. FIG. 14 b shows the data with interpretation by Dr. Hardage.

FIGS. 15 a and 15 b are a common-depth-point brute stack of datagenerated with a half-octave (32-48 Hz) wavelet. The shaded eventappears to be the Eagle Ford Shale. FIG. 15 a shows the data with nointerpretation by Dr. Hardage. FIG. 15 b shows the data withinterpretation by Dr. Hardage.

DETAILED DESCRIPTION OF THE INVENTION

Defined Terms

-   “target of interest” is a subsurface geological unit of economic    interest,-   “target” means target of interest,-   “formation” is a general subsurface geological unit that is not    necessarily considered a target of interest,-   “sector of interest” is a part of the target of interest,-   “source” is a unit that supplies energy such as acoustic energy,-   “source”, and “transmitter” are used interchangeably,-   “receiver” is an acoustic-to-electric converter that receives    acoustic energy,-   “array” is a collection of sources, receivers, or any other grouping    of devices arranged for a specific purpose,-   “real time” means work in process,-   “resonance” means increased amplitude of reflection of an object    subjected to energy waves by the source at or near its own natural    frequency of constructive interference,-   “distortion” means decreased amplitude of reflection of an object    subjected to energy waves by the source at or near its own natural    frequency of destructive interference,-   “resonant frequency” means a frequency at which resonance occurs,-   “distortion frequency” means a frequency at which distortion occurs,-   “harmonic” means any resonant frequency,-   “fundamental frequency” is the lowest non-zero resonant frequency,-   “period of resonance” is the range of frequencies between two    resonant frequencies or distortion frequencies,-   “narrowband” is a range of frequencies significantly less than the    period of resonance of the target of interest at the fundamental    frequency,-   “broadband” is a range of frequencies greater than a narrowband,-   “bandlimited” means narrowband,-   “resolution” means the ability to separate two features, such as    closely spaced reflection interfaces,-   “trace” is a record of received seismic signals,-   “stack” is a composite record made by combining different records,-   “Interactive” means adjusting the acoustic source in real time    typically based on data received from the receivers,-   “Impedance” means the product of density and velocity, and-   “reflection coefficient” means the ratio of the amplitude of the    reflected wave to that of the incident wave. Note: a low impedance    layer over a high impedance layer will produce a positive    reflection, and a high impedance layer over a low impedance layer    will produce a negative reflection.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

In FIGS. 1 a and 1 b source 101 and receiver array 103 are shownutilized on earth surface 104, or in an open borehole 113 of anyorientation, which is preferably a vertical or near-vertical borehole.

FIG. 1 a illustrates an embodiment in which bandlimited source 101 andreceiver array 103 are placed on surface 104.

FIG. 1 b illustrates an embodiment in which a bandlimited source 101 isplaced in wellbore 113 and receiver array 103 is placed on surface 104.

In use, source 101 transmits bandlimited vibratory waves 105 into ground106, which, after reflecting off the interfaces of target of interest107, are sensed or measured by appropriately positioned receivers 102 inarray 103.

When source 101 is activated, it generates downgoing vibratory waves 105within narrowbands, which propagate through underground formations 106to target of interest 107.

Reflections of these waves from interface 108, between upper formation106 a and target of interest 107, and interface 109 between target ofinterest 107 and lower formation 106 b, return as bandlimited upgoingwaves 110 to receivers 102 at the surface.

In an exemplary embodiment, a sector of interest 111 can be studiedusing an array of receivers 103, which process the received bandlimitedupgoing waves 110. From the receivers they can be utilized as inputs toadjust source 101 through optional feedback loop 112.

FIGS. 2 a and 2 b illustrate the impingement of bandlimited waves 105 inFIG. 1 on top 201 and base 202 of the target of interest for anormal-incidence reflection.

FIG. 2 a shows the impingement of a sinusoid having a period equal totwice the target thickness upon the two interfaces. Frequency f is equalto the inverse of the period or f=1/t, where t is the period of thewave. Assuming a low impedance target, with a deflection to the right(FIG. 2 a) being positive and equal and opposite coefficients ofreflection, the wave 203 reflected from top 201 and the wave 204reflected from base 202 are shown side-by-side. In this case trough 205from top reflected wave 203 aligns with trough 206 from bottom reflectedwave 204, yielding constructive interference.

FIG. 2 b shows the impingement of a sinusoid having a period equal tothe target thickness upon the two interfaces. Once again, the wave 203reflected from top 201 is shown side-by-side with the wave 204 reflectedfrom base 202. In this case, trough 207 from top reflected wave 203aligns with peak 208 from bottom reflected wave 204, thereby creatingdestructive interference.

FIG. 3 shows a plot of amplitude vs. twice the product of frequency fand target thickness T with odd harmonics, which occur for the case ofreflection coefficients with opposite sign. In this example, thereflection coefficients are also equal in magnitude. Destructiveinterference occurs at odd integer values of twice the product offrequency and target thickness. The plot shows fundamental odd frequency301 as a member of the set of odd harmonics 302 that repeat at everypoint fr=n+1/2, where n is a real positive integer or zero. The odddistortion frequencies 303 repeat according to fT=n.

FIG. 4 shows a plot of amplitude vs. twice the product of frequency andtarget thickness with even harmonics, which occur for the case ofreflection coefficients with the same sign. In this example, thereflection coefficients are also equal in magnitude. Constructiveinterference occurs at even integer values of twice the product offrequency and target thickness. The plot shows fundamental evenfrequency 401 as a member of the set of even harmonics 402 that repeatat every point fT=n, where n is a real positive integer or zero. Theeven distortion frequencies 403 repeat according to fT=n+1/2.

In practice, most reflection coefficient pairs cannot be equal inmagnitude, in which case they can be decomposed into even and oddcomponents. Also, the number of harmonics that are actually useful forimaging can be small and can depend strongly on the signal-to-noiseratio.

FIG. 5 shows a dual plot of amplitude vs. frequency and illustrates thethickness-dependant frequency response of two different targets. Theperiod of resonance P is equal to the inverse of the target thickness orP=1/T where T is the target time thickness in seconds. Thus, thickertargets show a smaller resonance period. The response period for a 10 msthick target 501 is compared with the response period for a 50 ms thicktarget 502.

FIGS. 6 and 7 show plots of the amplitude of the response of target 107in FIG. 1 vs. frequency for an odd pair, where T=20 ms. Filteringeffects are neglected for emphasis.

FIG. 6 illustrates the substantial difference in the response amplitudefor a bandlimited signal 601 centered on a resonant frequency at 25 Hzas opposed to a bandlimited signal 602 centered on a distortionfrequency at 50 Hz. Accordingly, the signal-to-noise ratio will be muchgreater for the bandlimited signal centered on the resonant frequency.

FIG. 7 shows the increased average amplitude of the target response fora 20-30 Hz narrowband signal 701 centered on a resonant frequency f=25Hz over the target response for a 10-60 Hz broadband signal 702.Accordingly, the signal-to-noise ratio will be greater for thebandlimited signal centered on the resonant frequency than for abroadband signal.

FIG. 8 shows a possible target of interest, which could be a thin sandtarget encased in shale. The uppermost formation 801 and the lowermostformation 803 enclose a thin layer 802.

Other exemplary targets of interest can be other layers, faults orfractures.

FIG. 9 shows a seismic apparatus 900 having a bandlimited seismic source901 optimally positioned next to a receiver 902 on earth surface 904.When source 901 is activated, it transmits downgoing vibratorynarrowband waves into the ground. After reflecting off sectors ofinterest 911, these waves return as bandlimited upgoing waves toreceiver 902 at the surface.

The signals generated by receiver 902 are passed to a signal conditioner908, which amplifies, filters and converts the analog signals to digitalsignals. The resulting digital signals are passed to a processor 909,which converts them into image signals.

The digital image signals from processor 909 are passed to imagingmeans, illustrated as a display 910, which can be a conventionalblack-and-white or color monitor. The digital signals from processor 909are also passed to a digital data collector 912.

In operation, an operator of apparatus 900 controls the output signalsfrom source 901 through a signal adjuster 905 that is designed tocontrol the source and its energy output.

The operator evaluates the images presented on display 910 and decideswhether the video signals have been optimized. If the answer is yes, theacquisition data are stored in data collector 912 and data collectioncontinues. If the answer is no, the operator uses signal adjuster 905 toadjust the output of source 901 until the image on display 910 moreclosely approximates the optimal harmonic resonance response expectedfrom sector of interest 911.

A memory unit (not shown) in processor 909 stores information indicativeof the received bandlimited return signals, which can be furtherprocessed depending on future needs. A communication device (not shown)in apparatus 900 can allow for direct communication with remotelylocated control units.

Using a feedback loop from processor 909 to adjuster 905, the desiredsource output adjustments could be executed automatically, therebyallowing the operator to intervene only as a troubleshooter.

Exemplary Methods

Referring to FIG. 10, exemplary methods of exploring a subsurface regionthat contains a target sector of interest will be described. At a step1000, information about the harmonic response for the target sector ofinterest is provided. The information may be the actual or estimatedharmonic response, or an approximation of the harmonic response. Asdescribed herein, the information can be based on one or more of avariety of sources, such as extant data from a well log, extant seismicdata, data determined by adjusting a transmitted narrowband to determinethe harmonic response, or based on other information about the probableharmonic response for the target sector of interest. These data can bestored on a computer-readable medium, such as magnetic storage orsemiconductor storage devices.

At step 1002, a seismic source is provided, as described hereinabove. Asstep 1004, the seismic source is controlled to provide seismic waves inone or more narrowbands selected on the basis of the informationprovided in step 1000. This step of controlling can comprise adjusting auser input device of a computing device coupled to the seismic source.Alternatively, the step of controlling can comprise loading from amemory the information about the harmonic response. Other methods ofcontrolling the seismic source are contemplated.

At step 1006, the seismic source is activated to introduce seismic wavesinto the subsurface region. At step 1008, reflections of the seismicwaves are sensed at a seismic receiver.

As described above, additional processing steps can be implemented withthe steps of FIG. 10. For example, seismic data collected prior to steps1006 and 1008 can be used to assist in the processing of data based onthe sensed reflections of step 1008. The seismic data collected prior tosteps 1006 and 1008 can be data collected using a broadband sweep offrequencies, which can be one, two, four, or any multiple of thebandwidth of the narrowband or narrowbands used in the method of FIG.10. Broadband seismic data collected before, during, or after any of thesteps in FIG. 10 can be used to facilitate at least one of acquisition,processing, and interpretation of the seismic data collected usingnarrowbands. For example, velocities and static corrections obtainedfrom broadband data processing can subsequently be used in theprocessing of the narrowband data. In one example, narrowbands can beused to detect a target sector of interest and broadband data, collectedbefore, after, or in conjunction with the narrowband data, can be usedto improve image resolution of the target sector of interest. In anotherexample, a narrowband can be used to detect a target sector of interestand a plurality of optimal narrowbands across a spectrum (e.g., at leasttwo, three, four or more narrowbands) can be used to improve the imageresolution of the target sector of interest using seismic inversion ofthe combined narrowbands in the time or frequency domains.

Sources

Conventional sources in the above mentioned prior art include surfaceacoustic sources, downhole seismic sources, swept frequency boreholesources, tunable frequency land and marine seismic vibrators,feedback-controlled vibrators, orbital vibrators, programmable acousticsources that are controlled by a computer, sources that are clampedagainst the borehole wall, and others.

The preferred seismic energy source for practicing the method of thisinvention is a controlled-frequency adjustable acoustic source capableof transmitting frequencies within narrowbands. It can be positioned onthe surface or inside a borehole. It can be conveyed into an openborehole by any known means such as production tubing, coiled tubing,cable, wireline, etc.

The source can produce bandlimited vibratory waves either simultaneouslyor sequentially, which can be held constant for some predeterminedduration, or can be varied incrementally. When the source is activatedit transmits vibratory waves into the ground within narrowbands, which,after reflecting off the targets of interest, are sensed and measured bythe appropriately positioned receivers.

Receivers

A conventional receiver has long been a velocity measuring geophone.However, accelerometers are becoming more widely utilized, andmulti-axis, or multi-component, accelerometers are emerging.Multi-component three axis sensing has produced superior images of thesubsurface as compared to single component sensing.

Receivers provide signals indicative of the sensed seismic energy to anacquisition device that can be co-located with the receiver unit andcoupled thereto for receiving the signal. A memory unit is disposed inthe acquisition device for storing information indicative of thereceived signal. A communication device can also be co-located with thereceiver/acquisition unit for allowing direct communication with aremotely located control unit.

In the crosswell or interwell seismic technique, the source is placed ina borehole and the receivers are placed in adjacent boreholes. Whenusing a reverse vertical seismic profiling technique, the source isplaced in a borehole and the receivers are placed along the surface asshown in FIG. 1 b. In the long spacing sonic technique, both the seismicsource and the receiver are placed in the same borehole. The crosswelltechnique is preferred. Both the source and the receivers can also beplaced on the surface as shown in FIG. 1 a.

Bandlimited Data Acquisition

When correlated to the harmonics of a specific target of interest, eachreceived bandlimited segment will have improved accuracy over broadbandcollection due to elimination of many waves that are not conducive toimaging, such as those created by uncontrolled seismic energy sources.

Through the production of energy within selected multiple narrowbands,the details of individual geologic targets of interest becomeaccentuated. This is because each target of interest responds optimallyto energy produced within specific narrowbands centered on harmonics.

Harmonic resonance occurs when the bandlimited reflections from twointerfaces are in phase as shown in FIG. 2 a, thereby producing anamplified reflection that is the sum of the reflection coefficients.

Harmonic distortion occurs when the bandlimited reflections from the twointerfaces are 180 degrees out of phase as shown in FIG. 2 b, in whichcase the amplitude will be the difference between the reflectioncoefficients. If the reflection coefficients are equal, harmonicdistortion results in complete destruction of the signal.

If the reflection coefficients are equal in magnitude and opposite insign, the response will show odd harmonics as shown in FIG. 3. If thereflection coefficients are equal in magnitude and equal in sign, theresponse will show even harmonics as shown in FIG. 4. In the generalcase, the response will be some combination of these two components, inwhich case the larger component will dominate.

Once the fundamental frequency of a given target of interest has beendetermined by adjusting the frequency of the source, other harmonicswill occur at a period that is the inverse of the thickness of thetarget of interest.

A target of interest with a given thickness will respond preferentiallyto energy produced at one set of harmonics, while a target of interestwith another thickness will show a peak response to energy produced atanother set of harmonics as shown in FIG. 5.

The central or peak frequency of the bandlimited waves applied by thesource should be appropriate for the depth of penetration necessary toimage the target of interest.

The range of narrowbands will occur within the range of seismicfrequencies, which is generally between 10 Hz and 250 Hz, although thisrange can vary depending on the source and other specific imagingconditions.

Bandlimited collection of data can focus on a single target of interestor multiple targets of interest. For example, the data collection effortcan focus on a petroleum reservoir, or on a petroleum reservoir togetherwith the surrounding or encasing formations, or stacked petroleumreservoirs, each of which can have a distinct optimal narrowband forimaging.

Real Time Bandlimited Data Acquisition

Based on information received by the receivers, real time interactivefrequency adjustments to the source can be made by an operator or by afeedback loop so as to induce harmonic resonance within the targets ofinterest.

By utilizing the harmonic response properties of the target of interestto make real time adjustments to the narrowband signals, the target ofinterest can be quickly and optimally imaged.

For example, if a target of interest is more optimally illuminated byone narrowband than by an adjacent narrowband, generally the narrowbandwith the superior response is closer to the harmonic resonance of thetarget of interest.

The speed with which accurate subsurface images can be obtained is oftencrucial to operations in the oilfield. Decisions involving theexpenditure of vast sums of money are often necessarily made on shortnotice due to practical considerations, such as equipment schedulingand/or downtime.

Real time bandlimited data acquisition of the exemplary embodimentsenables an operator to interact directly during the data collectionprocess.

The novel method reduces processing expenses significantly by permittinginteractive real time adjustments to acquisition parameters thatoptimize target of interest response. Utilization of the narrowbandproducing harmonic resonance of the target of interest can reduce theprocessing time and inaccuracies inherent in current spectraldecomposition methods, which can produce large volumes of data.

By focusing the acquisition on the naturally occurring harmonicresonance of the target of interest, significant non-pertinent data canbe eliminated from consideration.

Eliminating the non-pertinent data intrinsically improves both theaccuracy of the data and the speed with which a quality subsurface imagecan be produced. This also permits the tailoring of data acquisition andprocessing to the requirements of each unique application by reducingthe volume of non-pertinent data.

The data collected using the method of the exemplary embodiments,including the data which are not used for immediate application, can bestored and made available for future analysis involving otherapplications, which are presently known or which can be developed atsome future date.

Narrowbands can be collected independently of each other. However, ifthe signal-to-noise ratio is high at multiple harmonics, the narrowbandscan be combined in ways that optimize the imaging of the subsurfacetarget. Simply adding the time series of narrowbands centered ondistinct harmonics will produce a more resolved image.

Thus, when used in conjunction with traditional stacking methods, thesignal-to-noise ratio can be increased by narrowband imaging whilemaintaining resolution by combining multiple narrowbands.

Accordingly, a target of interest can be imaged at harmonics byinputting much less energy into the ground than would otherwise berequired by the use of an uncontrolled energy source.

Earth-Filtering Effects

Earth filtering effects can modify and degrade the seismic signal. Bymaking on the spot frequency adjustments in real time while knowing theseismic source, earth filtering effects can be better estimated andremoved.

Traditionally, earth-filtering effects are removed by applyingmathematical processes designed to remove these effects to the receivedseismic signal. Knowledge of the original bandlimited source signatureprovides additional constraints on the overall estimation offrequency-dependant earth filtering effects.

Spectral Information

Time-lapse reservoir 4D monitoring simply repeats former surveyspecifications, both in terms of source and receiver location and, forthe method of this invention, source frequency ranges.

In one application, spectral information together with the instantaneousknowledge of the source signature can be used to guide selection ofsubsequent acquisition parameters for time-lapse monitoring, savingprocessing time and cost.

For a specific target, the need to estimate the narrowband parameters ofthe source is eliminated after the initial data collection effort. Thus,a priori knowledge of the optimal source signature parameterscorresponding to the harmonics of the target of interest will improveaccuracy and save time.

The angle of incidence of the reflection received from a given point ona target of interest is determined by the vertical position of the toolin the wellbore, the depth and orientation of the formation, theposition of the receiver, and the physical parameters of the subsurface.

In one application, if the narrowband data are collected at variousdepths in adjacent wellbores, frequency-dependant AVO data can becollected. AVO stands for amplitude variation with offset.

AVO techniques known in the art provide estimates of acoustic and shearwave impedances for the media on either side of a reflecting interface,which are dependent on the parameters of the target of interest,including lithology, porosity, and pore fluid content. These estimatesare based on various approximations to the Zoeppritz formulation ofreflection coefficient variation as a function of incidence angle.

By collecting data within narrowbands, AVO attribute analysis isimproved. For example, utilization of frequency-dependant AVO attributeseliminates the need for bandwidth balancing.

Using “real” data as opposed to mathematically deconstructed data, thecurrent method provides improved imaging, thickness estimation, andfrequency-dependant AVO.

It is also anticipated that the method of this invention will improvethe quality of the estimates of attenuation for gas reservoirs.

Use of Extant Data

Useful information about target harmonic resonance can be gained fromwell log data. Well logging uses non-seismic frequencies and acquiresinformation within a radius of a few feet from a well bore. Well logdata are acquired using a well log device, and the data can be storedfor future use or study. One means of approximating a formation harmonicresponse utilizing well log data is through the use of the formula:

HR=V _(ave)/4Td+n(V _(ave)/2Td)

where HR is the peak harmonic response, V_(ave) is the average formationvelocity from a sonic well log, Td is formation distance thickness inmeters obtained from a well log for a formation having reflectioncoefficients with opposite sign at top and base, n=1, 2, 3, . . . Z,where Z references the maximum resonant frequency within the achievableseismic bandwidth in the harmonic response equation. Other calculationsor methods can be used to determine a harmonic response for a targetsector of interest or otherwise to select one or more initialnarrowbands for exploring a subsurface region. The information from thewell log can be stored in a computer and the processing circuitry of thecomputer can be configured to calculate one or more initial narrowbandsfor exploring the subsurface region, such as by calculating a harmonicresponse or peak harmonic response of a formation. The computer can bethe same computer which controls the seismic source, or a differentcomputer, and the calculation can be done just prior to exploration orat an earlier time.

Extant seismic data can be a useful source of information about thetarget harmonic response. One means of estimating a formation harmonicresponse utilizing pre-existing seismic data is through application ofknown time (Widess, M., 1963, How Thin is a Thin Bed? Geophysics, 38,1176-1180) and frequency (Liu, J. and K. J. Marfurt, 2006, Thin bedthickness prediction using peak instantaneous frequency: 76^(th) AnnualInternational Meeting Society of Exploration Geophysicists, ExpandedAbstracts, 968-972) thickness estimation techniques. For example, in theWidess method, thickness is estimated from the amplitude decay curve ofthe broadband data as the target layer thins below the point of maximumconstructive interference.

In certain applications, information from extant seismic data can beused to facilitate one or more of the acquisition, processing andinterpretation of the narrowband data focused on harmonic resonance ofthe target(s). For example, broadband data and narrowband data can becollected at the same receiver locations using sequential vibroseissweeps as one exemplary source. The processing parameters, for examplestacking velocities and surface consistent static corrections, derivedfrom the broadband data can be applied directly to the narrowband dataprocessing flow. The data can be manipulated by any type, variationand/or combination of acquisition or processing techniques, for thepurpose of achieving the best image quality for interpretation of thetarget(s) contained within the data. The resulting processed narrowbanddata can show improved detection of the target formation(s) to thebroadband data, where detection may refer to the ability to identify atarget in the data and resolution may refer to the ability to separatethe top and base of a particular target in the data.

Noise & Signal-To-Noise Ratio

In the art of geophysical imaging, which includes the acquisition andprocessing of data, the primary factor limiting the quality of seismicimages is that of noise. The presence of noise in the seismic datadiminishes the interpretability of the image.

More noise results in substandard image quality, which can obscure thetarget of interest. It is therefore highly desirable to mitigate theseproblems by increasing the signal-to-noise ratio.

There are different types of noise, and they can be dealt with indifferent ways. On the processing side, noise can be reduced byalgorithmic data processing. Filtering in the frequency-wave numberdomain can reduce ground roll. Frequency filtering can also reducerandom noise, although the filter can also affect the signal.

One technique used in geophysics for cancellation of random noise isthat of stacking. In this technique, reflections from a common midpointare added together to increase the signal. Because the noise is random,it is out of phase and statistically tends to cancel when addedtogether.

On the acquisition side, ground role or surface wave noise is suppressedby positioning the receivers so that the relative responses of theindividual receivers to the surface wave energy cancel each other out.This is an example of coherent noise reduction.

In accordance with this embodiment, the signal-to-noise ratio isimproved through utilization of the periodically repeating resonanceresponse of the target of interest, which is determined by the targetthickness and reflection coefficient ratio.

In the plot of amplitude vs. frequency, the signal-to-noise ratio issimply the ratio of the area under the curve of the signal to that ofthe area under the curve of the noise.

Because random noise tends to be white or flat across the spectrum,regions of the spectrum centered on resonant frequencies of the targetof interest will have a higher signal-to-noise ratio than those centeredon the distortion frequencies as shown in FIG. 6.

Also, regions of the spectrum centered narrowly on resonant frequencieswill have a higher signal-to-noise ratio than a broadband signal, asshown in FIG. 7.

Therefore, focusing the data acquisition on the regions in the vicinityof the resonant frequencies maximizes the signal-to-noise ratio, aspreviously described.

The following expressions give the area under the curve for a plot ofamplitude of reflectivity vs. frequency for a typical target ofinterest, which might be a sand encased in shale as in FIG. 8, and

with thickness T=20 ms and an odd reflection coefficient pair r1=−0.1,and r2=0.1, utilizing

a broadband signal f=10-60 Hz, and

a bandlimited signal f=20-30 Hz

$\begin{matrix}{{\int_{10}^{60}{\left\lbrack {2r_{o}{\sin \left( {\pi \; {fT}} \right)}} \right\rbrack \ {f}}} = \left( {2r_{o}} \right)} \\{\begin{Bmatrix}{{\left\lbrack {{{- 1}/\pi}\; T\; {\cos \left( {\pi \; {fT}} \right)}} \right\rbrack \left( {f = 60} \right)} -} \\{\left\lbrack {{{- 1}/\pi}\; T\; {\cos \left( {\pi \; {fT}} \right)}} \right\rbrack \left( {f = 10} \right)}\end{Bmatrix}} \\{= 6.37}\end{matrix}$ $\begin{matrix}{{\int_{20}^{30}{\left\lbrack {2r_{o}{\sin \left( {\pi \; {fT}} \right)}} \right\rbrack \ {f}}} = \left( {2r_{o}} \right)} \\{\begin{Bmatrix}{{\left\lbrack {{{- 1}/\pi}\; T\; {\cos \left( {\pi \; {fT}} \right)}} \right\rbrack \left( {f = 30} \right)} -} \\{\left\lbrack {{{- 1}/\pi}\; T\; {\cos \left( {\pi \; {fT}} \right)}} \right\rbrack \left( {f = 20} \right)}\end{Bmatrix}} \\{= 1.97}\end{matrix}$

If the signal-to-noise ratio for the 10-60 Hz case is 10, then the noiselevel will be 0.637.

Assuming white noise, the noise level for 20-30 Hz will be 0.137,yielding a signal-to-noise ratio of 1.97/0.137=14.38.

Thus, by the method of this embodiment, the use of a narrowband in thisexample has improved the signal-to-noise ratio by about 44%.

Advantages & Benefits in Time & Investment

Some of the advantages of one or more embodiments described herein:

provide an improved image without the necessity of detailed spectraldecomposition analysis;

can also be used in a marine setting.

The seismic source can be controllable and frequency ranges can be tunedto the target of interest response.

Because the source takes advantage of the target of interest harmonicresponse, it can require less input energy to generate a satisfactorysignal-to-noise ratio for imaging.

In addition to location of the source, the source signal parameters forthe specific target of interest will be known and more easilyrepeatable, thereby permitting more accurate 4D reservoir monitoring.Repeatability of multiple bandlimited investigations will provide moreinformation on fluid migration patterns and vastly improve accuracy.

The costs and inaccuracies associated with algorithmic processing ofseismic data can be reduced.

The collection method can reduce or eliminate noise associated withuncontrolled sources by not collecting it. This includes signals atdistortion frequencies not useful for imaging.

Field Testing

Field testing was performed to demonstrate that optimal seismic imagingof a targeted geological unit will occur if that geologic unit isilluminated by a seismic wavefield using a narrow band of frequenciesthat resonate with the dimensions of the targeted unit rather than by awavefield that has a broad band of frequencies as is used inconventional seismic data acquisition.

The testing was performed by the Bureau of Economic Geology, of theUniversity of Texas, under the direction of Senior Researcher Dr. Bob A.Hardage. The term Constrained Frequency Illumination (CFI) is a termcoined by Dr. Hardage to describe the technical concept of generatingseismic wavefields with narrow frequency bands that resonate with aspecific geologic target.

Seismic data were acquired along a 2-D profile 4750 ft long thatextended across the Devine Test Site. A 60,000-lb International VehiclesInc. (IVI) Hemi 60 vertical vibrator was used as a source, 3-componentgeophones were deployed as surface-based sensors, and AscendGeo's3-channel, cable-free, Ultra boxes were utilized as the data-acquisitionsystem. The IVI Hemi 60 vertical vibrator has accurate phase control ofits base plate motion. The IVI Hemi 60 vibrator had Pelton Advance 4electronics for controlling base plate motion and was operated at a70-percent drive level to generate a 42,000-lb ground force.

The same constrained-frequency wavefields that were acquired by thesesurface-positioned geophones were also recorded by a 48-station verticalarray of 3-component geophones deployed in Well 9 on the test siteproperty. Because Well 9 was located at the interior of the 2-D surfaceprofile and was offset only 60 ft from the line of surface receivers,the vertical seismic profile (VSP) data and well log data acquired inthis well provided useful calibration data that aided the interpretationof the surface-acquired seismic records generated in this test. The48-station geophone array in Well 9 extended from the bottom of the well(3000 ft below ground surface) to a depth of 686 ft below ground level.

The Eagle Ford Shale extends across the Devine Test Site at a depth ofapproximately 2600 ft and was selected as an imaging target for testing.The subsurface geology along the line of profile was illuminated withthirteen (13) seismic wavefields that had different ranges offrequencies to evaluate the effect of constrained-frequency illuminationfor detecting the Eagle Ford Shale and its related geological units. TheVSP test data illustrated that a downgoing wavefield that was limited tocontinuous frequencies between 32 and 48 Hz created a reflection fromthe Eagle Ford Shale that had a higher signal-to-noise (S/N) ratio thandid reflections produced by other choices of constrained frequencies.However, an evaluation of the surface-recorded data showed that the bestillumination of the Eagle Ford Shale occurred when the frequency contentof the illuminating wavelet was constrained to a slightly lowerfrequency range centered near 30 Hz. Such surface-recorded waveletsresponded to the Eagle Ford Shale better than did a wavelet constructedwith a broad 4-octave frequency range.

The results of this field test support the concept that a targetedgeological unit can be better imaged if the unit is illuminated by aproperly designed constrained-frequency wavelet.

The frequency band from 8 to 128 Hz was chosen as the frequency spectrumof the fundamental imaging wavefield. This 4-octave frequency band istypical of the broad-band sweep frequencies that are used inconventional seismic imaging of oil and gas reservoirs and their sealingunits. To demonstrate the effect of target illumination withconstrained-frequency wavefields, this 4-octave range of frequencies wassubdivided into its four single-octave components and then into itseight half-octave components to create the twelve constrained-frequencywavefields described in the right two columns of Table 1. The thirteenilluminating wavefields listed in this table were produced at eachsource station along the 2-D test profile and at each of the twooffset-source stations used to generate VSP data in Well 9.

TABLE 1 Frequency Content (in Hz) of Illuminating Wavefields 4-OctaveRange Single-Octave Band Half-Octave Band 8-128  8-16  8-12 16-32 12-1632-64 16-24  64-128 24-32 32-48 48-64 64-96  96-128

To ensure that adequate energy was associated with each frequencycomponent of each constrained-frequency wavefield, a linear sweep ratespanning 24 seconds was used when generating each illuminatingwavefield. Although the principal imaging targets were relativelyshallow (2500 to 3000 ft deep), a long listen time of 3 seconds wasutilized to ensure that shear-wave reflections from deep interfaces canbe analyzed if future data-processing activity focuses on theconverted-shear and direct SV shear modes generated by the verticalvibrator used in this experiment.

The surface-recorded data acquired for each of the wavelets listed inTable 1 were converted into common-depth-point (CDP) stacks so thatimaging quality could be compared between wavelet options. Eachconstrained-frequency image profile was created using identicaldata-processing steps and identical stacking velocities and staticcorrections. The data-processing sequence that was applied to the testdata is described by the steps listed on Table 2. The processing resultsare displayed as FIG. 11 a, b for the 4-octave wavelet. FIGS. 12 a, bthrough 9 d then display the results for the three CFI wavelets thatyielded the best images of the Eagle Ford Shale. All three of theseconstrained-frequency stacks show a more continuous Eagle Ford Shaleevent than does the 4-octave wavelet.

TABLE 2 Data Processing Steps 1. Correlate each sweep 2. Sort data intocommon-sweep data sets 3. Apply geometry to each data set 4. Apply datumcorrections Datum depth = 500 ft Replacement velocity = 10,000 ft/s 5.Apply trace mutes 6. Pick stacking velocities (4-octave data) 7. Stackeach data set 8. Apply surface-consistent statics 9. Restack each dataset with static corrections 10. Determine and CDP residual statics toeach data set 11. Apply FXDecon for noise attenuation

The half-octave (24-32 Hz) wavelet stack displayed as FIG. 12 a, b isparticularly good. A common feature of these three CDP stacks (FIGS. 12a, b, 13 a, b, 14 a, b) is that the imaging wavelets contain a largeamount of energy with frequency components in the range of 24 to 30 Hz.The CDP stack included as FIG. 15 a, b illustrates the reduced-qualityimaging result achieved with a 32-48 Hz wavelet.

The systems and methods described herein can be used for a variety ofimaging functions. In one example, a vertical fracture can be imaged. Inanother example, one or more of the methods can be used to improvefour-dimensional monitoring of CO₂ sequestration.

All publications, patents, and patent applications mentioned in thisspecification are herein incorporated by reference in their entiretiesto the same extent as if each individual publication, patent, or patentapplication were each specifically and individually indicated to beincorporated by reference.

The descriptions given herein, and best modes of operation of theinvention, are not intended to limit the scope of the invention. Manymodifications, alternative constructions, and equivalents can beemployed without departing from the scope and spirit of the invention.Accordingly, the scope of the invention should be limited only by theattached claims.

1. A method for exploring a subsurface region that contains a targetsector of interest, comprising: (A) providing (i) information from awell log about the harmonic response for the target sector of interestand (ii) a seismic source; (B) controlling the seismic source to provideseismic waves in a narrowband selected on the basis of the informationfrom the well log about the harmonic response for the target sector ofinterest; then (C) activating the seismic source so as to introduceseismic waves into the subsurface region; and (D) sensing reflections ofthe seismic waves at a seismic receiver.
 2. The method of claim 1,wherein the information from the well log about the harmonic responsefor the target sector of interest conveys information about a peakresonant frequency of the target sector.
 3. The method of claim 1,wherein the information from the well log about the harmonic responsefor the target sector of interest conveys information about resonancebetween reflecting surfaces of the target sector.
 4. The method of claim1, wherein the information about the harmonic response for the targetsector of interest is known a priori from the well log.
 5. The method ofclaim 1, wherein the step of controlling comprises controlling theseismic source to provide seismic waves in a frequency bandsubstantially centered on a resonant frequency estimated from theinformation from the well log.
 6. The method of claim 1, wherein thenarrowband is pre-selected on the basis of extant information about thesubsurface sector from the well log.
 7. The method of claim 1, wherein aplurality of narrowbands are provided by the seismic source based on theinformation from the well log about the harmonic response for aplurality of different geologic targets of interest.
 8. The method ofclaim 1, wherein the target sector of interest comprises a fracture andthe sensed reflections detect the fracture.
 9. The method of claim 1,wherein the sensed reflections are used for four-dimensional monitoringof CO₂ sequestration.
 10. A method for exploring a subsurface regionthat contains a target sector of interest, comprising: (A) providing (i)information from extant seismic data about the harmonic response for thetarget sector of interest and (ii) a seismic source; (B) controlling theseismic source to provide seismic waves in a narrowband selected on thebasis of the information from the extant seismic data about the harmonicresponse for the target sector of interest; then (C) activating theseismic source so as to introduce seismic waves into the subsurfaceregion; and (D) sensing reflections of the seismic waves at a seismicreceiver.
 11. The method of claim 10, wherein the information from theextant seismic data about the harmonic response for the target sector ofinterest is based on a peak resonant frequency of the target sector. 12.The method of claim 10, wherein the information from the extant seismicdata about the harmonic response for the target sector of interest isbased on resonance between reflecting surfaces of the target sector. 13.The method of claim 10, wherein the information about the harmonicresponse for the target sector of interest is known a priori from theextant seismic data.
 14. The method of claim 10, wherein the step ofcontrolling comprises controlling the seismic source to provide seismicwaves in a frequency band substantially centered on a resonant frequencyapproximated by the information from the extant seismic data.
 15. Themethod of claim 10, wherein the narrowband is pre-selected on the basisof extant information about the subsurface sector from the extantseismic data.
 16. The method of claim 10, wherein a plurality ofnarrowbands are provided by the seismic source based on the informationfrom the extant seismic data about the harmonic response for a pluralityof different geologic targets of interest.
 17. A method for exploring asubsurface region that contains a target sector of interest, comprising:(A) providing (i) information about the harmonic response for the targetsector of interest and (ii) extant seismic information and (iii) aseismic source; (B) controlling the seismic source to provide seismicwaves in a narrowband selected on the basis of the information about theharmonic response for the target sector of interest; (C) activating theseismic source so as to introduce seismic waves into the subsurfaceregion; and (D) sensing reflections of the seismic waves at a seismicreceiver, wherein the extant seismic information facilitates at leastone of acquisition processing and interpretation of the seismic data.18. The method of claim 17, wherein the extant seismic informationfacilitates acquisition of the seismic data.
 19. The method of claim 17,wherein the extant seismic information facilitates processing of theseismic data.
 20. The method of claim 17, wherein the extant seismicinformation facilitates interpretation of the seismic data.